Fluid composition for stimulation in the field of oil and gas production

ABSTRACT

A fracturing carrier fluid for fracturing a subterranean formation has at least one linear or branched hydrofluorocarbon compound having a boiling point, at a pressure of 1 atmosphere, of between 0° C. and 65° C. A fracturing fluid is also disclosed having the fracturing carrier fluid and proppants. A method for fracturing a subterranean formation using the fracturing fluid is also disclosed.

This application claims the benefit of priority of U.S. ProvisionalApplication No. 62/098630, filed Dec. 31, 2014, and French ApplicationNo. FR 14 63515, filed Dec. 31, 2014, the entireties of whichapplications are incorporated herein by reference.

The present invention relates to the treatment of fluid-bearingformations with fracturing fluids.

Subterranean fluids of economic value are usually obtained from asubterranean formation via a well penetrating the formation. Fluidscoming from subterranean fluid-bearing formations may be water which isfor example used as a geothermal source of heating, drinking water or asource of salts. Fluids coming from subterranean fluid-bearingformations may also be oil or gas or gas condensed in its liquid stateduring its flowback towards the surface also called condensate.

Unfortunately subterranean fluid-bearing formations, and especially manyoil and gas bearing subterranean formations, are more and more difficultto exploit on an economical point of view and require the use ofspecific methods and equipments to enhance the extraction of thesubterranean fluids through extraction wells. Typical enhancement of theproduction of wells may be obtained by treatment of the formation toincrease the output of subterranean fluids, such as oil and gas.

Generally such enhancement of the production of wells is achieved withthe use of water that is injected in (an)other well(s) penetrating thesubterranean formation, called injection well(s) or injector(s), inorder to maintain the pressure of the subterranean formation at asufficient level so that an economic flow from the subterraneanformation to the surface through the producing well(s) is obtained.However productivity enhancement may not be stable over time because ofplugging that may occur within the porosity of the subterraneanformation near the producing well or near the injection well.

Beside oil and gas wells that are not capable of continuing to produceeconomically and require stimulation of production by treatment of theformation to increase the output of oil and/or gas, there also existsubterranean formations which can not produce hydrocarbons after aborehole is drilled and a well is installed to penetrate thesubterranean formation. One of the reasons is because they naturallyhave a very low permeability like the ones associated with shale oil,shale gas, tight oil, tight gas and coal bed methane that hinders theflow of fluids.

And even for subterranean formations that produce fluids in alreadyeconomically conditions, it may be desired to still increase theirproduction levels.

A common and known method of stimulation treatment is fracturing.Conventionally carrying out such a treatment comprises injecting aliquid suspension, the fracturing fluid, down into the wellbore and backinto the formation to the extent necessary so as to improve fluidpermeability, usually because the number and/or size of passageways orfractures in the formation is increased. The fracturing fluid generallycomprises the fracturing carrier fluid and solid particles.

To create the fractures, the fracturing fluid is injected at highpressure, and in this case a high pressure pumping equipment isnecessary. Usually solid particles are also injected with the fracturingfluid in order to maintain the fractures opened. Such solid particles,also known as propping agents or “proppants”, are dispersed into thefracturing carrier fluid and then transported down to the fracturesduring the high pressure pumping operation.

Injection is continued until a fracture with sufficient dimensions isobtained to allow the right and correct placement of propping agents.Once the proppants are in place, the injected fluids are let to leak offinto the formation until the fracture gets sufficiently thinner to holdthe proppants in place. The wellhead pressure is then lowered and thefluid is pumped back.

Proppants are usually granular materials, typically sand. Other commonlyused proppants include resin-coated sand, intermediate-strength proppantceramics, and high-strength proppants such as sintered bauxite andzirconium oxide. Numerous but less common proppants include plasticpellets, steel shot, glass beads, high strength glass beads, aluminumpellets, rounded-nut shells, and the like.

In order for the treatment to be successful the fracturing fluid,usually oil or water in the liquid phase, must be removed from the welltypically to avoid the clogging of the hydrocarbons of the subterraneanhydrocarbons bearing formation. In many instances this is a difficultproblem which involves considerable expenditure of time and money.Present-day treatments of wells generally require the use of largevolumes of fracturing fluid.

For example, during fracturing treatment, wells, especially horizontalwells, commonly require as much as 20,000 tons of aqueous fracturingfluid. Before production from the reservoir can be resumed, asubstantial portion if not all of the aqueous fracturing fluid must beremoved there from. This represents an appreciable expenditure of timeand pumping costs.

Nowadays, the most successful fracturing methods use water as thecarrier fluid, more precisely either viscosified water or slickwater.Due to the higher cost of oil compared to that of water as thefracturing carrier fluid, oil fracturing is limited to subterraneanformations that are sensible to water. Indeed, some formations containspecific clays that will swell when in contact with water impairing thepermeability even in the presence of the fractures. However oilgenerally contains organic pollutants like benzene which iscarcinogenic, toluene which causes serious damage to health by prolongedexposure through inhalation, ethylbenzene and xylene, which will contactand dilute into water in the subterranean formation with a risk ofpollution once at the surface. Benzene, Toluene, Ethylbenzene andXylene, also called BTEX are listed by the EPA in the Clean Air Act of1990 as some of the 188 hazardous air pollutants.

Furthermore, some areas where stimulation is used have high constraintson the supply of water, e.g. Texas in the U.S.A. Other places havefarming lands or living places in their neighborhood, making itnecessary a high quality for the treatment of the flow back waterspumped back to the surface after the fracturing operations are run andbefore these waters are discharged.

Dow Chemicals proposed in 1966 (see e.g. U.S. Pat. No. 3,368,627) afracturing method that uses a combination of C2-C6 hydrocarbons andcarbon dioxide as the fracturing fluid. The mixture is designed to get acritical temperature sufficiently high or a critical pressuresufficiently low to remain liquid at the temperature and pressureexisting during injection down the well, but also a critical temperaturesufficiently low or a critical pressure sufficiently high for asubstantial portion of such injected fluid to be converted to a gas upona release of the pressure applied to the liquid during injection.

Indeed, the critical temperature and pressure are important parametersfor a fracturing fluid able to be in the state of a gas. Below thecritical temperature, a fluid can exist as a solid and/or a liquidand/or a gas depending on pressure and temperature. Above the criticaltemperature, a fluid can exist as a gas and/or a supercritical fluiddepending on the pressure and temperature. If the reservoir temperatureis higher than the critical temperature of the fracturing fluid, theliquid fracturing fluid will undergo a phase transition upon heating tosupercritical fluid during the injection. The supercritical fluid hasdensity and viscosity higher than that of a gas at the same temperatureand lower than that of a liquid at the same pressure. So the friction ofproppants with the carrier fluid is lower when the carrier fluid is insupercritical state than when it is in liquid state. In this way thesettling of the proppants due to gravity, which have a higher densitythan the carrier fluid, is higher in the horizontal parts of the surfaceequipments, wells and fractures when the fracturing carrier fluid is insupercritical state. The settling of proppants is characterized by thesettling velocity of the proppant particles. Avoiding settling, or atleast minimizing settling, is important in order to maximize thetransport efficacy which could be slowed down by frictions of theproppant particles with the surface of the piping equipments and thefracture walls. Hence minimizing or avoiding settling in equipments andfractures increases the probability for the proppants to reach thefractures and limits accumulation of proppants in horizontal parts ofthe equipments and fractures. Hence the proppant transport efficiency islower when the settling velocity is higher, and this is for example thecase when the fracturing carrier fluid is in supercritical state ratherthan when it is in liquid state.

This patent U.S. Pat. No. 3,368,627 proposes a solution to avoid the useof water and reduce the amount of energy needed to pump the fracturingfluid back to the surface. However this method employs two fluids, inthe gaseous phase at ambient pressure and temperature, which must becompressed to get them liquid, which increases the number of equipments.What's more, carbon dioxide is difficult to compress owing to itscritical is point: the high critical pressure (7.3 MPa) and low criticaltemperature (31° C.) makes it necessary to compress the gas at pressureabove 7.3 MPa and/or cool it down to temperatures below 31° C. to get itliquid.

Attempts were made to simplify the method and use only one carrier fluidother than water to suspend the proppants. “Oil and Gas Journal”, Jul.5, 1971, page 60, describes a gelled liquid gas useful for fracturinggas wells. The gelled liquid gas contains carbon dioxide, liquidpetroleum gases, a gelling material and proppants. Viscosifying thecarrier fluid, or gelling it, is useful to allow a more efficienttransport of the proppants by increasing the friction between them andthe carrier fluid. In this way the settling of the proppants due togravity, which have a higher density than the carrier fluid, is limitedin the horizontal parts of the surface equipments, wells and fractures.

Patent U.S. Pat. No. 3,846,310 discloses the use of a mixture of a firstalkoxide of a group IA metal and a second alkoxide of a group IIIAelement as the gelling agent for a hydrocarbon carrier fluid like forexample liquefied petroleum gas, heptane. In the presence of water, thegelling agent is said to go into the water phase, thus reducing thehydrocarbon viscosity. It is said that in the treatment of a gas orcondensate producing formation, it is preferred that the liquidhydrocarbon be volatile at reservoir conditions. During injectionoperations, the liquid hydrocarbon is under pressure and retains itsliquid state. When the applied pressure is relieved, the liquid will betransformed into a highly mobile vapor because of its volatility at thereservoir conditions thereby promoting rapid well cleanup. In placeswhere there is no water in the subterranean formation, the gellingagent, that does not evaporate, will remain in the subterraneanformation leading to deposits blocking the fractures and reducing theflow of hydrocarbons originally present in the subterranean formation.This limitation also applies for the publication in “Oil and GasJournal”, Jul. 5, 1971, page 60.

Another drawback of patent U.S. Pat. No. 3,846,310 is the use ofheptane. Under 1 atmosphere (101.325 kPa), this alkane has a boilingpoint of 98° C., whereas that of toluene is 111° C. As the boilingpoints are close to each other (less than 20° C. difference) this wouldrequire an expensive equipment to separate both compounds in order toavoid pollution of heptane by toluene.

More recently US2011284230 claims a method of treating subterraneanformations, the method comprising introducing a hydrocarbon fracturingfluid comprising liquefied petroleum gas into the subterraneanformation, subjecting the hydrocarbon fracturing fluid to pressuresabove the formation pressure, and shutting-in the hydrocarbon fracturingfluid in the subterranean formation for a period of at least 4 hours. Itis also said the hydrocarbon fracturing fluid produced by the abovemethods may comprise at least one gelling agent, and that the gellingagent may be any suitable gelling agent for gelling LPG, includingethane, propane, butane, pentane or mixtures of ethane, propane, butaneand pentane.

However when a gelling agent is used, the problem is the formation ofdeposits once the pressure is relieved. If the pressure is not relievedenough to get evaporation of the hydrocarbons of the fracturing fluid,there is a risk when said fracturing fluid is pumped back to thesurface. This will be difficult because of the high viscosity of thegelled fracturing fluid. In such cases, breakers may be used to reducethe viscosity. Conversely this adds more complexity with the control ofdosage and delayed action time of the breaking agent on the gellingagent.

When no gelling agent is used, then the viscosity of LPG, includingethane, propane, butane, pentane or mixtures of ethane, propane, butaneand pentane is very low and the proppant transport efficiency is low.

ECorp Stimulation Technologies (see http://www.ecorpintl.com/) promotesthe use of propane as fracturing fluid without gelling agent. Carriedunder liquid form, propane is injected with sand or ceramics. Almost allof the injected propane (from 95% to100%) is said to flow back in theform of gas, due to the natural phenomenon of pressure differencebetween the subterranean formation and the surface. The recoveredpropane is said to be re-used for stimulation operations, or re-injectedin pipelines with the rest of the extracted gas. This technologyunfortunately has poor efficiency to transport the proppants.

ECorp Stimulation Technologies also promotes the use of a fluorinatedpropane derivative which is 1,1,1,2,3,3,3-heptafluoropropane. Thismolecule is also known as a refrigerant under code name R-227ea, inaccordance with the American Society of Heating, Refrigerating and AirConditioning Engineers Standard 34 (ASHRAE, 2010a and 2010b). R-227ea ispromoted as a stimulation fluid, in order to completely eliminate therisk associated with the flammability of regular propane. It is saidthat no water and no chemical additive is used in with theheptafluoropropane and that, as for regular propane, heptafluoropropanewould be recovered under a gaseous form for an immediate or futurere-use. R-227ea is said to be easily separable from components ofnatural gas extracted from the well, especially propane and butane.

Although this technology allows for recycling possibilities and betterproppant transport efficiency than liquid propane, its proppanttransport efficiency is lower than that of water except between 35° C.and 60° C. where it is equivalent owing to precision on calculation aswill be exemplified. Particularly R-227ea has a lower efficiency totransport the proppants than water as will be exemplified, at atemperature above 60° C., which temperature is met in all shaleformations.

The high volatility of R-227ea is also a drawback when the fracturingfluid is prepared and injected at a relatively high ambient temperature,for example about 40° C. and higher, as this may occur in hot locationssuch as Texas. Blenders are used to mix the proppants with the carrierliquid fluid. Proppants held in blenders at the well site for use asproppant in the fracturing operation may reach temperatures such as 65°C. due to the exposure of the blenders to the sun. When proppants andthe carrier liquid fluid are blended, some of the liquid carrier fluidmay change phase resulting in lower liquid volume. To avoid this it isnecessary to keep the fracturing carrier fluid liquid at such atemperature by increasing the pressure inside the blender or to cool itdown, making it more costly.

What is more, the separation with butane makes it necessary to use 2steps: first a condensation of butane which is less volatile (boilingpoint at a pressure of 1 atmosphere (101325 Pa), that is Normal BoilingPoint or NBP, is 0° C. for n-butane whereas the NBP of R-227ea is -16°C.), and then a condensation of R-227ea which is in the gas phase afterthe first condensation.

Patent application US2014/0251623 discloses the use of media that caninclude non-gelled liquid alkanes, halogenated hydrocarbons, foamedhydrocarbons, propylene carbonate, and fluidized solid proppant materialfor performing fracturing operations. The aim is to provide media havinga reduced flammability as compared to known used alkanes. The proposedmedia recite certain specific halogenated hydrocarbons. However thosehalogenated hydrocarbons are in the gas state at ambient temperature andpressure, so that they are not easily handled and stored under theseconditions, with high risks of leakage.

There is therefore still a need for fracturing fluids that do notcontain water while being at least as efficient as or more efficientthan water-based fracturing fluids. There is also still a need forfracturing fluids that do not contain water and that are easily handledand stored at ambient temperature and pressure, There is also still aneed for fracturing fluids that do not contain water, that do notcontain carcinogenic products and that are easily recyclable asfracturing fluids without being polluted by benzene, toluene,ethylbenzene and xylene.

Despite continuous searches since 1966, there is still a need foralternative and/or enhanced fracturing carrier fluids that alleviate thedrawbacks of the fracturing carrier fluids from the state of the art.

The inventors have now discovered that a above objectives are reached inwhole or at least in part with the fracturing carrier fluids of thepresent invention which is detailed is herein below.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows the settling velocity in different fluids, including fluidsaccording to embodiments of the present disclosure, as a function of thetemperature.

FIG. 2 shows the settling velocity values, as a function of thetemperature, for various fracturing carrier fluids according toembodiments of the present disclosure, as well as for water.

DETAILED DESCRIPTION

The aim of the present invention is to provide a fracturing carrierfluid with one or more, preferably all the following features:

-   -   the fracturing carrier fluid is non aqueous, i.e. no water is        added on purpose,    -   the fracturing carrier fluid is of low toxicity compared to oil        and more generally has a low environmental impact,    -   the fracturing carrier fluid is easily transformed into a liquid        or a gas, and vice-versa, upon temperature variations and/or        pressure variations,    -   the fracturing carrier fluid allows for a settling velocity        equal to or lower than that of known fracturing carrier fluids,        on the widest temperature range possible, e.g. between 20° C.        and 200° C., preferably between 70° C. and 190° C., for a given        size and nature of proppant,    -   the fracturing carrier fluid allows for a settling velocity        equal to or lower than that of water, on the widest temperature        range possible, e.g. between 20° C. and 200° C., preferably        between 30° C. and 190° C., more preferably between 30° C. and        140° C., for a given size and nature of proppant,    -   the fracturing carrier fluid is easy to separate/recover from a        flowback fluid (e.g. containing natural gas, condensate or oil,        etc.),    -   and the fracturing carrier fluid is easily transformed back into        liquid state.

In the following description of the present invention, the belowdefinitions and methods will be used:

-   -   the environmental impact of solvents is measured by the        Greenhouse Warming Potential (GWP) relative to carbon dioxide        for 100 year integration and by the Ozone Depletion Potential        (ODP). GWP of R-227ea is 3220 and ODP is 0. GWP of propane is 20        and ODP is 0;    -   Normal Boiling Point (or NBP) is the boiling point at a pressure        of 1 atmosphere (101325 Pa);    -   the proppant transport efficiency is assessed with the settling        velocity of a single spherical solid particle (proppant) in the        carrier fluid due to gravity at a given temperature        corresponding to the subterranean hydrocarbon formation        temperature; the lower the settling velocity, the longer the        time for the proppant particles to settle down.

In a first aspect, the present invention relates to a fracturing carrierfluid for fracturing a subterranean formation, said fracturing carrierfluid comprising at least one linear or branched hydrofluorocarboncompound having a boiling point of between 0° C. and 65° C.

In the present invention, “hydrofluorocarbon” means a compound withcarbon, hydrogen, fluorine and optionally chlorine atoms. The selectionof the appropriate fracturing carrier fluid is depending on the NormalBoiling Points of the recovered hydrocarbons: according to a preferredembodiment, the Normal Boiling Point of the appropriate fracturingcarrier fluid has a difference of at least 10° C., preferably 20° C.,more preferably 25° C., above or under the Normal Boiling Point of therecovered gaseous hydrocarbon that has the highest (respectively lowest)Normal Boiling Point among the mixture of recovered gaseoushydrocarbons. This renders easier the recovery, e.g. by distillation, ofthe fracturing carrier fluid.

According to still a preferred embodiment, the Normal Boiling Point ofthe fracturing carrier fluid is at least 10° C., preferably 20° C., morepreferably 25° C., above the Normal Boiling Point of the recoveredgaseous hydrocarbon that has the highest Normal Boiling Point among themixture of recovered hydrocarbons, e.g. for butane, above 0° C.

Among these appropriate fracturing carrier fluids, preferred are thosehaving a high Normal Boiling Point, preferably higher than 0° C., morepreferably higher that 10° C., more preferably higher than 20° C. Mostpreferred fracturing carrier fluids are those having a Normal BoilingPoint above ambient temperature, so that the fracturing carrier fluidsare liquid a ambient temperature and thus easily separated from theother recovered gaseous hydrocarbons at ambient temperature andpressure. Another advantage of such fracturing carrier fluids that areliquid at ambient temperature is their easiness in storage and use.

These issues regarding easiness of separation and Normal Boiling Pointsvalues is of importance, especially considering the separation anddistillation/condensation installation. Particularly used are separatorsand dehydrators that usually work at a temperature between 100° C. and150° C. to separate oil, gas and condensate as defined above. Therefore,and as another still preferred embodiment, the most appropriateracturing carrier fluids have a NBP below 100° C. to be easily separatedfrom the recovered hydrocarbons (liquid or gaseous) and then condensedagain in the gas treating units comprising separators, compressors, heatexchangers, and the like. The same applies for separations,distillations or condensations at pressure above atmospheric pressure.

As an other preferred embodiment the fracturing carrier fluids accordingto the present invention has a critical pressure (P ₁ lower than 7 MPa,preferably lower than 5 MPa so that the compression tools that are usedfor the transportation into the gas lines may also be used for thecondensation of the fracturing carrier fluids.

For the sake of low toxicity once recycled, it is also desirable thatthe NBP of the fracturing carrier fluid is far from that of benzene,toluene, ethylbenzene and xylene which are respectively 80° C., 111° C.,136° C. and around 140° C. Hence a NBP below 60° C. is preferred wherethe recovered hydrocarbons comprise one or more components chosen fromamong benzene, toluene, ethylbenzene and xylene.

Hence, an appropriate fracturing carrier fluid, besides its NBP between0° C. and 65° C., preferably meets at least one and preferably two ofthe following requirements: a) ODP strictly lower than 0.02, preferably0.01, and more preferably equal to 0; and b) Critical Pressure equal toor less than 7 MPa, preferably equal to or less than 5 MPa.

According to a preferred aspect, the appropriate fracturing carrierfluid for use in the present invention has a NBP between 0° C. and 65°C. and a Critical Pressure equal to or less than 7 MPa, preferably equalto or less than 5 MPa.

According to another preferred aspect, the fracturing carrier fluid ofthe invention has a critical temperature equal to or greater than 110°C. and equal to or lower than 200° C.

According to still a preferred embodiment of the present invention, theat least one linear or branched hydrofluorocarbon compound is of formula(1):

C_(n)H_(m)F_(p)X_(q)   (1)

wherein n, m, p and q respectively represent the number of Carbon atoms,Hydrogen atoms, Fluorine atoms and X atoms, with n≧3, m≧0, p≧1, qrepresents 0 or 1 or 2, and X represents an halogen atom different fromfluorine, and wherein the compound of formula (1) has a Normal BoilingPoint (NBP) of between 0° C. and 65° C., preferably of between 5° C. and60° C., more preferably of between 10° C. and 55° C.

It is understood that when q is equal to 2, the X atoms may be the sameor different. Preferably q is 0 or 1. It is also understood that the sum(m+p+q) is equal to or is less than 2n+2, where n, m, p and qrespectively represent the number of Carbon atoms, Hydrogen atoms,Fluorine atoms and X atoms in the compound of formula (1).

Preferably X represents chlorine, bromine or iodine, more preferablychlorine or bromine, still more preferably X represents chlorine.

According to a preferred embodiment, n represents 3 or 4 or 5,preferably n represents 3 or 4. According to another preferredembodiment, m is such that 0≦m≦11. According to still another embodimentp is such that 1≦p≦12.

The carbon atoms in the compound of formula (1) may be arranged inlinear or branched chain. Preferably, the compound of formula (1) has 0or 1 carbon-carbon double bond. Preferably the compound of formula (1)has 1 carbon-carbon double bond when q is equal to 2.

According to a particularly preferred embodiment of the presentinvention, the compound of formula (1) above has a critical temperatureequal to or greater than 110° C. and equal to or lower than 200° C.,preferably equal to or greater than 130° C. and equal to or lower than200° C.

According to a particularly preferred embodiment of the presentinvention, the compound of formula (1) above has the formulaC_(n)H_(m)F_(p)X_(q) with n is 3 or 4, 0≦m≦7, 3≦p≦9, and q represents 0or 1. Also preferred are compounds of formula (1) wherein each of thecarbon atoms bears at least one fluorine atom.

Non limiting examples of compounds of formula (1) that are useful in thepresent invention, include 1,1,1,3-tetrafluoropropane,1,1,2,2,3-pentafluoropropane, 1,1,1,3,3-pentafluoropropane,1,1,1,2,3,3-hexafluoropropane, 1,3-difluoropropane,1-chloro-3,3,3-trifluoropropene, 1,1,3,3-tetrafluoropropane, 1,2,2,3-tetrafluoropropane, 1,1,1,2,2,4,4,4-octafluorobutane,1,1,1,2,2,3,3,4-octafluorobutane, 1,1,1,2,2,3,3,4,4-nona-fluorobutaneand mixtures of two or more of them, in any proportions.

The thermodynamic properties of the compounds of formula (1), as definedabove with their critical temperature and NBP, allow for easy handlingof fracturing carrier fluid as well as easy separation of the fracturingcarrier fluid from the recovered hydrocarbons. Moreover it hassurprisingly been discovered that fracturing carrier fluids comprisingat least one fluorinated compound of above formula (1), with the abovementioned thermodynamic characteristics concurring to easy handling anduse, allow for a proppant settling velocity in the fracturing carrierfluid that is equal to or lower than in known fracturing carrier fluids,and as close as possible to or preferably lower than the settlingvelocity in water, within a wide range of subterranean formationtemperatures, preferably between 20° C. and 200° C.

According to another preferred embodiment, the fracturing carrier fluidof the invention has a critical pressure lower than 70 bar (7 MPa),preferably lower than 50 bar (5 MPa), whereas carbon dioxide (00₂) has acritical pressure of 73 bar (7.3 MPa). This is therefore anotheradvantage of the fluid of the present invention which is liquid at alower pressure value, in other words a lower pressure is sufficient toget the fracturing fluid liquid.

Furthermore, the use of compounds of formula (1) presents manyadvantages, particularly as compared to the use of water as fracturingcarrier fluid. Among those advantages may be cited: poor, or absence, ofsolubilization of mineral salts present in the subterranean formations,and therefore cheaper and easier recycling process of the fracturingcarrier fluid, lower impact on the subterranean formation integrity(e.g. minimized swelling or absence of swelling of the subterraneanformation), and the like.

According to a preferred embodiment, the fracturing carrier fluid of theinvention does not contain any toxic and environmentally harmfularomatic compounds, such as benzene, toluene, ethylbenzene and xylene,contrary to known fracturing oils that may still be used.

The fracturing carrier fluid may also comprise one or more additiveswell known by the skilled in the art. Examples of such additivesinclude, as a non limiting list, biocides, corrosion inhibitors,surfactants (e.g. fluorosurfactants), scale inhibitors, anti-foamingagents, rheology modifiers (e.g. viscosity enhancers, drag reducers, . .. ) and the like, as well as mixtures of two or more of the above citedadditives in all proportions.

For example, drag reducers are used to reduce the friction and enablethe increase of the flowrate at constant pumping, biocides are used toprotect the drag reducer from biodegradation, corrosion inhibitors areused to protect the equipments from corroding, surfactants are used toincrease the wetting of the fracturing fluid on equipment surfacesand/or help its foaming, scale inhibitors are used to avoid scaledeposition from the water of the formation.

According to another aspect, the present invention relates to afracturing fluid comprising at least one fracturing carrier fluid asdefined above and proppants. Proppants that may be used in thefracturing fluid of the invention are any kind of proppants known by theskilled in the art, and are usually in the form of granular materials.Typically proppants include sand, resin-coated sand,intermediate-strength proppant ceramics, high-strength proppants such assintered bauxite and zirconium oxide, plastic pellets, steel shot, glassbeads, high strength glass beads, aluminum pellets, rounded-nut shells,and the like.

Proppants that may be used are of all types known in the art from USmesh 12 to US mesh 100, preferably from US mesh 20 to US mesh 100. Thelargest proppants generally are sieved with sieves of US mesh 20 and USmesh 40, that is to say they pass through a sieve with a mesh size of850 μm and do not pass through a sieve with a mesh size of 425 μm. Suchproppants are especially fitted for use in slickwater.

The proppant concentration generally is comprised between 20 grams and600 grams per liter of fracturing carrier fluid, more preferably between25 grams and 250 grams per liter of fracturing carrier fluid.

Still according to a further aspect, the present invention relates to afracturing method of a subterranean formation using the fracturing fluidas defined herein above. The fracturing method of the present inventioncomprises at least the following steps:

a) providing a fracturing carrier fluid comprising at least one compoundof formula (1) as defined above, i.e. comprising at least one compoundof formula (1) as defined above, with optional compressing and/orcooling, so that the fracturing carrier fluid is in the form of aliquid;

b) preparing a fracturing fluid by mixing the liquid fracturing carrierfluid of step a) with proppants in a vessel so as to obtain a liquidfracturing fluid; and

c) injecting the said liquid fracturing fluid of step b) (i.e. a liquiddispersion), into a subterranean formation at a pressure sufficient toopen one or several fractures therein.

Compression at step a) may be realized with any method known by theskilled artisan and for example with a pump, up to a pressure above theequilibrium gas-liquid pressure. Cooling at step a) may be realized withany method known by the skilled artisan and for example with a heatexchanger to a temperature below the equilibrium gas-liquid temperature.

Before step a) of the method according to the invention, thesubterranean formation may be pre-treated by injecting the fracturingcarrier fluid of the invention as a liquid without proppants, and/or byinjecting liquid water and/or liquid hydrocarbons and/or a foam composedof water or hydrocarbons mixed with a gas. According to anotheralternative, the formation may be flushed after step c) by injecting thefracturing carrier fluid of the invention without proppants or liquidwater or liquid hydrocarbons or eventually a foam composed of water orhydrocarbons mixed with a gas.

The method of the invention can be preceded and/or combined and/orfollowed with one or more known fracturing methods, which make use ofslickwater, gelled water, hydrocarbons, gelled hydrocarbons, foamfluids, and the like.

The method of the invention may also comprise the recycling of any ofthe fracturing fluid or pre-treatment fluid or flushing fluid, whichcontains no proppant, or at least a little amount of proppant(s). Thisrecycling of the fracturing carrier fluid of the invention, after itsuse as fracturing fluid or pre-treatment fluid or flushing fluid for afracturing operation, comprises at least the steps of:

-   -   recovering, with pumping and/or with decompression (e.g. return        to normal pressure), at least a portion of the fluid and a        portion of the hydrocarbons originally present in the formation,        the fluid being the fracturing carrier fluid, from the        hydrocarbon reservoir to produce the recovered fluid; and    -   separating from the recovered fluid the fracturing carrier fluid        to get a gas or a liquid, alone or in admixture with        hydrocarbons, with any technique known in the art, including for        example one or several separator(s), one or several        dehydrator(s), variations of temperature, pressure and time, and        the like.

As described above, the fracturing carrier fluid for use in the presentinvention allows for reduced settling particle velocity of the proppantthat is dispersed therein.

The theoretical settling velocity (v₁) of a single smooth sphericalparticle at a given equilibrium temperature and equilibrium pressure ina fluid is calculated using the following empirical equation (1) byFergusson and Church, published in “Journal of Sedimentary Research”,(Vol. 74, N° 6, November 2004, p. 933-937), corresponding to the maximumvelocity or terminal velocity or limit velocity:

$\begin{matrix}{{v_{1} = \frac{{Rgd}^{\; 2}}{{18\; v_{fluid}} + \sqrt{0.75 \times 0.4\mspace{11mu} {Rgd}^{\; 3}}}}{with}} & (1) \\{R = \frac{\Delta \; \rho}{\rho_{fluid}}} & (2)\end{matrix}$

and, substituting R of equation (2) in equation (1), results in thefollowing equation allowing for the calculation of the settling velocity“v₁”, expressed in m.s⁻¹:

$v_{1} = \frac{{gd}^{\; 2}\Delta \; \rho}{\left( {{18\; \eta_{fluid}} + \sqrt{0.75 \times 0.4\; d^{3}g\; \rho_{fluid}\Delta \; \rho}} \right)}$

wherein “v_(fluid”) is the kinematic viscosity of the carrier fluid,expressed as the ratio “η_(fluid)/ρ_(fluid)”, “η_(fluid)” is the dynamicviscosity of the carrier fluid in Pa.s, “g” is the gravity accelerationconstant (9.81 m.s⁻²), “d” is the particle diameter expressed in meters,is the carrier fluid density expressed in kg.m⁻³, and “Δρ” is thedifference of density between the particle and the carrier fluid in theliquid phase, expressed in kg.m⁻³.

In the following calculations the particle density is set as the valueof quartz density which is 2650 kg.m⁻³ because quartz sand is often usedas a proppant. As an example, a smooth particle with a 425 μm diameterand a 2650 kg.m⁻³ density has a settling velocity in the fracturingcarrier fluid of the invention lower than that in water over atemperature range equal to or greater than 65° C.-75° C. The same smoothparticle in the fluorinated hydrocarbon 1,1,1,2,3,3,3-heptafluoropropane(R227ea) has a higher settling is velocity than in water within thetemperature range of 10° C. to 190° C.

The critical pressure and critical temperature of a fluid are measuredas follows: the principle of the measurement relies on the variation ofthe heat capacity during the phase or state change upon heating at 0.2°C. per minute. A closed test cell is filled with about 1 g of the samplefluid and then let to thermally equilibrate before heating is started.The transition is detected by the heat flow exchanged by the test cellcontaining the sample fluid using a calorimeter that leads to theknowledge of the critical temperature defined by the onset point. Thecritical temperature is graphically defined as the temperaturecorresponding to the intersection of the slopes before and after thetransition in the heatflow curve (onset point).

The pressure in the cell is continuously measured during the heating ofthe test cell. The value of the pressure reached at the temperaturecorresponding to the critical temperature is directly read, andconsidering the experimental correction of the pressure transducer dueto the temperature effect on the transducer response which is measuredthrough calibration, the critical pressure is calculated. For thedetermination of the critical temperature and critical pressure, a C80calorimeter commercialized by Setaram is used. The precision on thecritical temperature is 0.5° C. and on the critical pressure 0.4 bar (40kPa).

To measure the liquid density in the liquid phase, the procedure used isto 1) clean and dry the vessel; 2) pull vacuum; 3) weigh the vessel; 4)charge said vessel with the test fluid; 5) weigh again said vessel toget the weight of the test fluid added; 6) allow the temperature toequilibrate to the test temperature; 7) record the liquid volume; 8)calculate the density.

The calculation method of the liquid density (in kg.m⁻³) is reproducedbelow with a definition of the variables:

${{{Liquid}\mspace{14mu} {density}} = {\frac{m_{liq}}{V_{liq}} = {\frac{\left( {m - m_{vap}} \right)}{V_{liq}} = {\frac{\left( {m - \left( {V_{vap} \times d_{vap}} \right)} \right)}{V_{liq}} = \frac{\left. \left( {m - \left( {\left( {V_{tot} - V_{liq}} \right) \times d_{vap}} \right)} \right) \right)}{V_{liq}}}}}},$

wherein

-   -   V_(tot) (total volume of vessel) is equal to V_(liq)+V_(vap),        where V_(liq) is the measured liquid volume in the vessel, and        V_(vap) is the gas volume in the vessel,    -   m (total mass of fluid added to vessel) is equal to        m_(liq)+m_(vap), where m_(liq) is the mass of liquid, and        m_(vap) is the mass of gas, and    -   d_(vap) is the gas density at temperature T.

The gas density is calculated using ideal gas law. The precision on thetemperature is 0.2° C. The precision on the liquid density is 0.1%.

To obtain the value of the dynamic viscosity, the measured kinematicviscosity is multiplied by the liquid density. The kinematic viscosityis measured using Cannon-Fenske Ostwald viscometers. The viscometers arecalibrated at each temperature with fluids of known viscosity. AnOstwald type viscosity tube consists of a glass tube in the shape of a Uheld vertically in a controlled temperature bath. In one arm of the U isa vertical section of precise narrow bore called the capillary. Abovethis is a bulb, there is another bulb lower down in the other arm. Inuse, liquid is drawn into the upper bulb by suction and then allowed toflow down through the capillary into the lower bulb. Two marks (oneabove and one below the lower bulb) indicate a known volume. The timetaken for the level of the liquid to pass between these marks isproportional to the kinematic viscosity.

Although the tubes are provided with a conversion factor, each tube usedin the reported measurement program has been calibrated by a fluid ofknown properties at each temperature. The time it takes for the testliquid to flow through a capillary of a known diameter of a certainfactor between two marked points is measured. By multiplying the timerequired by the factor of the viscometer, the kinematic viscosity isobtained. The viscometers were immersed in a constant temperature bathcontrolled to ±0.2° C. Viscosity data obtained using this procedure areaccurate to ±2%.

The calculation and measurement methods described above make it possibleto assess viscosity and density as a function of the temperature forprior art fracturing carrier fluids, and then to finally calculate thesettling velocity of a proppant in said prior art fracturing carrierfluids.

FIG. 1 shows the settling velocity in different fluids of the prior artas a function of the temperature. Taking into account the calculationprecision, a particle with a diameter of 425 μm and a density of 2650kg.m⁻³ has a settling velocity in R-227ea equivalent to that in water inthe range of temperatures 35° C-60° C., outside this range the settlingvelocity is higher than that in water.

R1234yf and R1234ze(E), each possessing 3 carbon atoms, 2 hydrogenatoms, 4 fluorine atoms and 1 carbon-carbon double bond, result insettling velocity always higher than that in water and are not part ofthe invention. FIG. 1 also shows the settling velocity in a fracturingcarrier fluid according to the invention, R-1233zd, which is equal tothat in water on a wider temperature range. R-1233zd which possesses 3carbon atoms, 2 hydrogen atoms, 3 fluorine atoms, 1 chlorine atom and 1carbon-carbon double bond results in a settling velocity lower than thatobserved in water in the range 50° C.-100° C. R-1233zd is part of theinvention.

Settling velocity values, as a function of the temperature, for variousfracturing is carrier fluids according to the invention as well as forwater, are presented in FIG. 2.

In R-245ca, which possesses 3 carbon atoms, 3 hydrogen atoms and 5fluorine atoms, a particle with a diameter of 425 μm and a density of2650 kg.m⁻³ has a lower settling velocity than in water in the range 10°C-140° C. R-245ca is part of the invention.

In R-245fa, which also possesses 3 carbon atoms 3 hydrogen atoms and 5fluorine atoms, a particle with a diameter of 425 μm and a density of2650 kg.m⁻³ has a lower settling velocity than in water in the range 25°C-105° C. R-245fa is part of the invention.

In R-236ea, which also possesses 3 carbon atoms, 2 hydrogen atoms and 6fluorine atoms, a particle with a diameter of 425 μm and a density of2650 kg.m⁻³ has a lower settling velocity than in water in the range 20°C-105° C. R-236ea is part of the invention.

Table 1 below shows some compounds of formula (1) that may be useful inthe implementation of the present invention: R-1233zd, R-245ca, R-245faand R236ea all have a NBP above 0° C. and a critical temperature above110° C.

TABLE 1 Compound NBP (° C.) Tc (° C.) R-227ea −16.3 102 R-1234yf −29.495 R-1234ze (E) −19 109 R-245fa 15 154 R-236ea 6 139 R-1233zd 20 165R-245ca 25 174

1. A fracturing carrier fluid for fracturing a subterranean formation,said fracturing carrier fluid comprising at least one linear or branchedhydrofluorocarbon compound having a boiling point, at a pressure of 1atmosphere (101325 Pa), of between 0° C. and 65° C.
 2. The fracturingcarrier fluid according to claim 1, having a critical temperature equalto or greater than 110° C. and equal to or lower than 200° C.
 3. Thefracturing carrier fluid according to claim 1, wherein the at least onelinear or branched hydrofluorocarbon compound is of formula (1):C_(n)H_(m)F_(p)X_(q)   (1) wherein n, m, p and q respectively representthe number of Carbon atoms, Hydrogen atoms, Fluorine atoms and X atoms,wherein n 3, m 0, p 1, q represents 0 or 1 or 2, and X represents ahalogen atom different from fluorine, and wherein the compound offormula (1) has a Normal Boiling Point (NBP) of between 0° C. and 65° C.4. The fracturing carrier fluid according to claim 3, wherein the atleast one linear or branched hydrofluorocarbon compound is of formula(1) with n is 3 or 4, 0 m 7, p 9, and q represents 0 or
 1. 5. Thefracturing carrier fluid according to claim 1, wherein the at least onehydrofluorocarbon compound is chosen form 1,1,1,3-tetrafluoropropane,1,1,2,2,3-pentafluoropropane, 1,1,1,3,3-pentafluoropropane,1,1,1,2,3,3-hexafluoropropane, 1,3-difluoropropane,1-chloro-3,3,3-trifluoropropene, 1,1,3,3-tetrafluoropropane,1,2,2,3-tetrafluoropropane, 1,1,1,2,2,4,4,4-octafluorobutane,1,1,1,2,2,3,3,4-octafluorobutane, 1,1,1,2,2,3,3,4,4-nonafluorobutane,and mixtures thereof.
 6. The fracturing carrier fluid according to claim1, further comprising one or more additives chosen from biocides,corrosion inhibitors, surfactants, scale inhibitors, anti-foamingagents, rheology modifiers, and mixtures thereof.
 7. A fracturing fluidcomprising at least one fracturing carrier fluid comprising at least onelinear or branched hydrofluorocarbon compound having a boiling point, ata pressure of 1 atmosphere (101325 Pa), of between 0° C. and 65° C. andat least one proppant.
 8. The fracturing fluid according to claim 7,wherein the at least one proppant is chosen from sand, resin-coatedsand, intermediate-strength proppant ceramics, high-strength proppants,plastic pellets, steel shot, glass beads, high strength glass beads,aluminum pellets, rounded-nut shells, and mixtures thereof.
 9. Thefracturing fluid according to claim 7, wherein the at least one proppantis present in a concentration between 20 grams and 600 grams per literof fracturing carrier fluid.
 10. Method for fracturing a subterraneanformation, comprising: a). providing a fracturing carrier fluidaccording to claim 1, with optional compressing and/or cooling, so thatthe fracturing carrier fluid is in the form of a liquid; b) preparing afracturing fluid by mixing the liquid fracturing carrier fluid of stepa) with at least one proppant in a vessel so as to obtain a liquidfracturing fluid; and c) injecting the said liquid fracturing fluid ofstep b), into a subterranean formation at a pressure sufficient to openone or several fractures therein.
 11. The method of claim 10 furthercomprising recycling of the fracturing carrier fluid.
 12. The method ofclaim 10 further comprising recycling of the fracturing carrier fluid,wherein said recycling comprises: recovering, with pumping and/or withdecompression, at least a portion of the fluid and a portion of thehydrocarbons originally present in the formation, the fluid being thefracturing carrier fluid, from the hydrocarbon reservoir to produce therecovered fluid; and separating from the recovered fluid the fracturingcarrier fluid to get a gas or a liquid, alone or in admixture withhydrocarbons.
 13. The fracturing carrier fluid according to claim 3,wherein the compound of formula (1) has a Normal Boiling Point (NBP) ofbetween 5° C. and 60° C.
 14. The fracturing carrier fluid according toclaim 3, wherein the compound of formula (1) has a Normal Boiling Point(NBP) of between 10° C. and 55° C.
 15. The fracturing fluid according toclaim 7, wherein the at least one proppant is present in a concentrationbetween 25 grams and 250 grams per liter of fracturing carrier fluid.